The increased production flow area provided by a horizontal, as compared to a vertical, wellbore has driven an increase in the drilling and completion of horizontal wells. Such wells have long open-hole sections which remain in contact with the drilling fluid for long periods of time in overbalanced conditions, forming a filter cake on the formation and also thereby initiating solids invasion that may induce formation damage. Regardless of the type of drilling conducted, the selection of drilling fluid has a major effect on minimizing skin development and maximizing fluid and gas production or injection.
Efficiency in the overall production of fluids and gases from a well or injection into a well is further highly dependent on the effectiveness of production and injection chemicals. Such production chemicals include completion fluids as well as treatment solutions for production stimulation. It is understood that chemicals and treatments used to improve production out of a well are also used to improve injection into a well.
Exemplary production chemicals include aqueous acid solutions which are often used to increase the permeability of a formation. Injection of the aqueous acid solution into the formation results in dissolution of mineral constituents, thereby producing flow channels. In such methods, difficulties are often encountered due to water-in-oil emulsions (having crude oil deposits as the outer phase) which are formed downhole at the interfaces between the injected aqueous treating solutions and crude oil contained in the formations. Solids and particulates, such as fines and insoluble reaction products, accumulate at the oil-water interfaces and stabilize the emulsions which in turn tend to plug the pore spaces in the formations being treated, thereby restricting the flow of the treating solutions and subsequent production of fluids therethrough. While a variety of additives having surface active properties have been developed for preventing the formation of emulsions, sludge, etc., as well as preventing the corrosion of metal surfaces, and have been included in the various treating solutions employed, less than desirable results are often achieved.
In addition, and particularly where aqueous acid treating solutions are utilized, sludge formed as a result of the reaction of the acid with asphaltic materials contained in the crude oil can plug the pore spaces of the formations.
Solids and particulates are known to negatively impact the overall efficiency of completion of wells. These include asphaltene, paraffin deposits and scales. Asphaltenes are most commonly defined as that portion of crude oil which is insoluble in heptane. Asphaltenes exist in the form of colloidal dispersions stabilized by other components in the crude oil. They are the most polar fraction of crude oil, and often will precipitate upon pressure, temperature, and compositional changes in the oil resulting from blending or other mechanical or physicochemical processing. Asphaltene precipitation occurs in pipelines, separators, and other equipment. Once deposited, asphaltenes present numerous problems for crude oil producers. For example, asphaltene deposits can plug downhole tubulars, wellbores, choke off pipes and interfere with the functioning of separator equipment.
Residues from drilling muds further negatively impact the overall efficiency of completion of wells. Commonly employed drilling muds are gaseous or liquid. Liquid drilling muds have a water base or an oil base. The aqueous phase of the more common water base muds may be formed of fresh water or a brine. As a discontinuous or disperse phase, water base fluids may contain gases or water-immiscible fluids, such as diesel oil, in the form of an oil-in-water emulsion, and solids including weighting materials, such as barite. Water base fluids also typically contain clay minerals, polymers, and surfactants for achieving desired properties or functions.
Oil base fluids are often referred to as oil based muds (OBM) and synthetic based muds (SBM). Most OBMs and SBMs are invert emulsions composed of an aqueous phase dispersed or surrounded by a continuous oil phase. OBM and SBM filter cakes, composed of colloid particles, weighting material, drilled solids and water or brine droplets dispersed in the oil phase, are hydrophobic and exhibit a permeability which is typically lower than the permeability of the formation.
Oil base fluids offer performance advantages over water base fluids. Such advantages include higher penetration rates, improved lubricity, shale stability, decreased fluid loss, and thinner filter-cake characteristics. In addition, oil base fluids provide gauge hole, higher rates of penetration and deeper bit penetration. Furthermore, fluid losses to the formation from oil base or synthetic oil base fluids tend to be less damaging since the base fluid is oil rather than water. Oil base fluids, however, are usually more difficult to remove due to the hydrophobic nature of the base fluid and impermeable nature of the deposited filter cake.
Solids and particulates not only cause a restriction in pore openings in the formation (formation damage) and hence reduction in the rate of oil and/or gas production, but also cause blockage of tubular and pipe equipment during production and surface processing. It is well known that production efficiency increases if such unwanted solids and particulates are removed from the wellbore.
To remove such particulates, the well is generally subjected to shut-in, whereby compositions are injected into the well, usually under pressure, and function to remove the unwanted particulates. Shut-ins are typically performed regularly in order to maintain high production or injection rates. Shut-ins constitute down time when no production or injection takes place. Thus, a reduction in total production or injection corresponds to the number of down times during the shut-in operation.
Production is further decreased when ineffective chemicals are used during shut-in. For instance, ineffective scale inhibitors fail to reduce total scale build-up. Poor displacement of drilling mud results in solid residues and mud residues left in the wellbore which, in turn, typically leads to formation damage, etc. Similar displacement or mud removal procedures are also performed before cementing. Mud residue can lead to weak bonding between cement and the formation surface and gas leakage when the well is turned to production.
The prior art has recognized the use of surfactants in the displacement and removal of oil base muds. Surfactants are first dissolved in fresh water or seawater at the concentration of 5 volume percent or more and the resulting liquid is then pumped at sufficient rate to generate turbulent flow to facilitate the mud cleaning process. Although surfactant systems have been widely used in field applications, their effectiveness is often limited by solvency capacity. In addition, the efficiency of surfactant systems varies for different muds and is negatively impacted by the condition of the mud when the displacement is conducted.
Historically, solvent- or aqueous-based systems have been used in mud displacement processes as well as in processes to effectuate the removal of oil based and synthetic oil based filter cakes. While aqueous surfactant based systems are generally selected over solvent treatments as mud displacement and mud filter cake clean-up treatments, surfactant systems are often ineffective. For instance, surfactant based systems are typically ineffective at breaking the emulsion inside the filter cake and effecting complete phase separation. Further, aqueous surfactant based treatments often create additional damage by forming an emulsion block with the formation oil. Such emulsion blocks have the potential to block production or injection. Further, such systems are either not biodegradable or are less efficacious than desired.
In most cases, due to strong solvency of the organic solvent toward the base oil in oil based mud, solvents have shown good mud removal and cleaning effects in both laboratory and field applications. However, pure organic solvent is generally expensive and often becomes cost prohibitive. Although water can be mixed with organic solvent to cut the fluid cost, the effectiveness of the system can be greatly reduced, even at levels as low as 10 to 20 volume percent of water content. In other cases, especially when solid content in the mud or mud residue is high and the mud viscosity is significant, pure solvent is often not effective.
Organic solvents are further often used in formation clean-up or near wellbore damage removal when the damage is caused by asphaltene or paraffin deposition as well as scale deposition. Very often the solvents are aromatic and leave an environmental footprint. In other cases, the solvent is not effective, especially when suspension and dispersion of solids is desired. Pure organic solvents cannot effectively break up solid aggregation and does not facilitate solid suspension.
Improved production chemicals are therefore desired for the treatment of fluid producing or injecting wells which are capable of removing or inhibiting the formation of unwanted solids and particulates within the well.
For instance, in order to meet more challenging drilling applications such as for use in deepwater and high-temperature, high-pressure (HTHP) applications, and further to meet stricter health, safety, and environmental standards, new systems to displace and/or remove OBM and SBM filter cakes have been sought. In particular, there is a need for new systems that do not cause the problems associated with the aqueous systems of the prior art and which further are biodegradable.